The efficiency of oil field operations such as drilling, well completion, and production depends on obtaining a suitable understanding of the structure and properties of the geological formations in the region of interest. To this end, oilfield operations perform various types of formation analysis using seismic surveys, downhole tools, and laboratory tools operating on samples retrieved to the surface. One example of formation or rock sample analysis involves nuclear magnetic resonance (NMR) phenomena.
NMR tools, whether embodied as a downhole tool or a laboratory instrument, generally include a magnet assembly that produces astatic magnetic field (B0), and a coil assembly that generates a perturbing magnetic field (B1), usually in the form of an electromagnetic radio frequency (RF) pulse sequence. With suitable signal frequencies and field strengths, hydrogen nuclei can be induced to create a sequence of echoes that decay (“relax”) in a characteristic fashion that represents an ensemble of spins de-phasing from each other. The decay rate is affected by the species of the spins and the local field homogeneity in the vicinity of the spins. The local field heterogeneity in reservoir rocks is primarily due to pore geometry, multi-phase fluid distribution, and the matrix minerals. A range of pore sizes, the surrounding matrix mineral distributions, and the fluid distribution in pore spaces results in multiplicity of relaxation times. With antennas to detect the echo sequence and processors to analyze the sequence, NMR tools can derive a spin-spin relaxation time (T2) distribution for a sample volume. Similarly, NMR tools can also detect the interaction of spins with the surrounding material (lattice), and derive a spin-lattice relaxation time (T1) distribution. Such distributions can each be correlated with various formation characteristics including pore size distribution and porosity distributions, among others.
In complex formations, particularly for carbonates, the pore structure is highly heterogeneous. This heterogeneity makes it difficult to establish analytical or empirical expressions that correlate well logging measurements with key “second order” material properties, such as pore connectivity, pore type, capillary pressure, or permeability. (Such properties are fundamental to determining efficient reservoir production strategies.) A typical approach for developing a petrophysical interpretation model for heterogeneous reservoirs uses a large number of core samples; this approach recognizes that a small number of samples fail to represent the reservoir rock system. However, it has been determined that, even with a large number of samples, it is difficult to find correlations that can serve as the basis for useful predictions and understanding of reservoir behavior.
It should be understood, however, that the specific embodiments given in the drawings and detailed description below do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and other modifications that are encompassed in the scope of the appended claims.